Pre-Caspian Basin Research Articles

Four‐dimensional Variability of Composite Halokinetic Sequences

AbstractThe architecture of salt diapir‐flank strata (i.e. halokinetic sequences) is controlled by the interplay between volumetric diapiric flux and sediment accumulation. Halokinetic sequences consist of unconformity‐bounded packages of thinned and folded strata formed by drape folding around passive diapirs. They are described by two end‐members: (a) hooks, which are characterized by narrow zones of folding (<200 m) and high taper angles (>70°); and (b) wedges, typified by broad zones of folding (300–1000 m) and low taper angles (<30°). Hooks and wedges stack to form tabular and tapered composite halokinetic sequences (CHS) respectively. CHSs were most thoroughly described from outcrop‐based studies that, although able to capture their high‐resolution facies variations, are limited in describing their 4D variability. This study integrates 3D seismic data from the Precaspian Basin and restorations to examine variations in CHS architecture through time and space along diapirs with variable plan‐form and cross‐sectional geometries. The diapirs consist of curvilinear walls that vary from upright to inclined and locally display well‐developed salt shoulders and/or laterally transition into rollers. CHS are highly variable in both time and space, even along a single diapir or minibasin. A single CHS can transition along a salt wall from tabular to tapered geometries. They can be downturned and exhibit rollover‐synclinal geometries with thickening towards the diapir above salt shoulders. Inclined walls present a greater proportion of tapered CHSs implying an overall greater ratio between sediment accumulation and salt‐rise relatively to vertical walls. In terms of vertical stacking, CHS can present a typical zonation with lower tapered, intermediate tabular and upper tapered CHSs, but also unique patterns where the lower sequences are tabular and transition upward to tapered CHS. The study demonstrates that CHSs are more variable than previously documented, indicating a complex interplay between volumetric salt rise, diapir‐flank geometry, sediment accumulation and roof dimensions.

An efficient optimization framework of cyclic steam stimulation with experimental design in extra heavy oil reservoirs

The Jurassic sandstone reservoir of the Pre-Caspian basin has abundant heavy oil resources. It has characteristics of high porosity, high permeability, shallow depth, and high crude oil viscosity. So the cyclic steam stimulation (CSS) is necessary to produce oil in an effective and economic way. However, the optimization of injection-production parameters for CSS is the premise of the technical strategies and development schemes. The conventional method usually adopts the one-parameter-at-a-time approach to perform sensitivity studies. This method is lack of interactions between different factors and difficult to determine the optimal level, in some situations even the main controlling factor is ignored.In our work, the experimental design method was used to consider the interactions of multiple injection-production parameters. The quantitative ranking of important factors was also determined. Based on geological characteristics and pilot test of the extra heavy oil reservoirs in Mortuk oilfield, the numerical simulation model was established. Firstly the two-level Plackeett-Burman experimental design was used to screen seven injection-production parameters for the CSS process. The first five parameters, the sum of their influencing weight larger than 98%, are steam injection intensity, production liquid rate, production time, steam quality and injection rate, respectively. Then the three-level Box-Behnken experimental design was used to perform optimizing studies. Two regression equations of cumulative oil production and cumulative oil steam ratio (COSR) were obtained on the basis of the response surface method, which fits very well with the numerical simulation results. Finally, the optimal values of uncertain factors were determined to maximize cumulative oil with relatively high COSR. This optimization framework is helpful for petroleum engineers to provide a quick evaluation of CSS.

The stratigraphic record of minibasin subsidence, Precaspian Basin, Kazakhstan

AbstractMinibasins are fundamental components of many salt‐bearing sedimentary basins, where they may host large volumes of hydrocarbons. Although we understand the basic mechanics governing their subsidence, we know surprisingly little of how minibasins subside in three‐dimensions over geological timescales, or what controls such variability. Such knowledge would improve our ability to constrain initial salt volumes in sedimentary basins, the timing of salt welding and the distribution and likely charging histories of suprasalt hydrocarbon reservoirs. We use 3D seismic reflection data from the Precaspian Basin, onshore Kazakhstan to reveal the subsidence histories of 16, Upper Permian‐to‐Triassic, suprasalt minibasins. These minibasins subsided into a Lower‐to‐Middle Permian salt layer that contained numerous relatively strong, clastic‐dominated minibasins encased during an earlier, latest Permian phase of diapirism; because of this, the salt varied in thickness. Suprasalt minibasins contain a stratigraphic record of symmetric (bowl‐shaped units) and then asymmetric (wedge‐shaped units) subsidence, with this change in style seemingly occurring at different times in different minibasins, and most likely prior to welding. We complement our observations from natural minibasins in the Precaspian Basin with results arising from new physical sandbox models; this allows us to explore the potential controls on minibasin subsidence patterns, before assessing which of these might be applicable to our natural example. We conclude that due to uncertainties in the original spatial relationships between encased and suprasalt minibasins, and the timing of changes in style of subsidence between individual minibasins, it is unclear why such complex temporal and spatial variations in subsidence occur in the Precaspian Basin. Regardless of what controls the observed variability, we argue that vertical changes in minibasin stratigraphic architecture may not record the initial (depositional) thickness of underlying salt or the timing of salt welding; this latter point is critical when attempting to constrain the timing of potential hydraulic communication between sub‐salt source rocks and suprasalt reservoirs. Furthermore, temporal changes in minibasin subsidence style will likely control suprasalt reservoir distribution and trapping style.

Characterization of Oligo-Miocene evaporite-rich minibasins in the Sivas Basin, Turkey

Abstract The Sivas Basin in Turkey displays in its central part an Oligo-Miocene halokinetic province which acts as a major outcrop analogue to study salt-sediment interactions. Based on field geology observations, the present paper focuses on the geometry and sedimentology of several minibasins having the particularity of being mainly filled by gypsiferous deposits. Such type of evaporite-rich minibasins remain difficult to identify and are poorly studied in other halokinetic provinces. In the Sivas Basin, the evaporites were recycled from diapiric salts and precipitated in saline ponds emplaced above deflating diapiric stems. Diapir deflation resulted either from local transtensive strain, cessation of diapir feeding and/or subsurface dissolution of the diapiric salt. Minibasin subsidence was likely enhanced by the fast emplacement rate of the capping evaporites, together with the high density of the depositional sulfates compared to the diapiric halite. The evaporite-rich minibasins stand out from their surrounding siliciclastic counter-parts by their small dimension (lower than 1 km-wide), their encased teardrop shape, and their high internal deformations. The later include well-developed halokinetic sedimentary wedges, aerial mega-slumps or inverted flaps. Such structural features probably resulted from the ductile rheology of the evaporite infill and the complex pattern of downbuilding. Although secondary evaporitic minibasins have never been identified in other ancient halokinetic settings, our study highlights that they could developed in any evaporitic environments, coastal or continental, such as in the Precaspian Basin. The secondary minibasins described here can also act as field analogues of other primary evaporite-rich minibasins already suspected in salt giant basins (e.g. in the Santos Basin, Brazil).

Increasing drilling speed in long horizontal intervals in Aktobe Kazakstan

The Aktobe project is at the east margin of the Pre-Caspian Basin, where horizontal well is mainly used to develop the low porosity and permeability layers. To improve production per well, the horizontal interval increased from +/-400m to +1000m. Due to complicated geological structure, variable boundary and thickness of target layers, the RSS was employed to improve the rate in layer. But the average ROP was just 2.36m/hr, and average footage was just 335m per bit due to high strength of the formation. To solve this problem, the wearing characteristic of PDC bits was analyzed. The BHA and table rotary speed were optimized on the basis of drilling pipe vibrating calculation. Thus, the drilling technology for hard and long horizontal interval, including high performance PDC bit, RSS, PDM, BHA with 1/2 stabilizer, has been worked out. The technology was used in 5 wells, of which 4 wells at 60 rpm, had stick-slip index of less than 80%, the drill bits out of the wells had few cutters broken by vibrating; 1 well had stick-slip index of higher than 80% at 70-80rpm, and the drill bits out of the well had many cutters broken by vibrating. Compared with Well H814, the horizontal section drilling time shortened from 22.5d to 9.6d, by 57.7%, ROP increased by 261.4%, and the footage increased by 195.5%. The optimized horizontal drilling technology for hard formation could provide reference for the drilling of similar hard formation, especially for the other oilfields in the Pre-Caspian Basin.

PALEOZOIC DEPOSITS MYNTOBINSKO-NOVOBOGATINSKAYA ZONE STRUCTURAL AND TECTONIC FEATURES ON THE SOUTH-WESTERN FRAME OF THE CASPIAN BASIN

Background The south-western border of the Pre-Caspian basin, to which the Myntobinsko-Novobogatinskaya uplift zone is confined, relates to the border zone with the territory of Russia adjacent to the west and north-west due to geographical factors. Historically, this band, called the Ural-Volga interfluve, was studied by Kazakhstan companies together with Russian specialists, whose contribution to the study of the regional and internal structure of Paleozoic sediments and the evaluation of oil and gas objects can be considered significant. Aims and Objectives Study the tectonic features of the Paleozoic sediments and the regional characteristics of the structural plan of the Caspian basin southern part. The research area is confined to the Myntobinsko-Novobogatinskaya zone of uplifts in the Ural-Volga interfluve. Results The main stages in the study of Paleozoic sediments and the favorable prerequisites obtained at the initial stage of the study, indicating a promising oil and gas bearing, are noted. The latest structural constructions characteristic according to reflecting horizons, local structures and their differentiation according to the shape and type of traps are given. On the basis of this, a forecast was made for lithofacies inside-basin zones: shallow water (carbonate paleoshelf), relatively submerged near-shore zone and deeper-water zone. The large Paleozoic uplifts correlation with anomalies of increased value magnetic field is given. Along with shallow carbonate areas development, the perspective of local uplifts of large amplitude and size within a relatively submerged nearshore zone and a deeper-water zone is accentuated. In areas with predominantly terrigenous and carbonate-terrigenous sedimentation, a large Paleozoic uplifts high prospect is predicted. The oil and gas potential of the Paleozoic deposits (Kobyakovskaya, Alga) was obtained on separate uplifts. Prospective local uplifts are grouped into larger objects - megauplifts (Edil, Kobyakovsko-Primorskoye, Peschanoye, and North-Coastal), which are genetically associated with elevated areas and projections of the foundation.

Hydrocarbon potential of deeply buried reservoirs in the Astrakhan oil and gas accumulation zone: problems and solutions

Global experience in oil exploration and the discovery of the Tupi field in Brazil and the Tiber field in the Gulf of Mexico in the last decade have confirmed the existence of giant oil fields with abnormally high formation pressures at depths of 10 km or greater. Until recently, the discovery of large oil accumulations in deeply buried reservoirs was considered as theoretically impossible. This work suggests that giant oil accumulations at great depths (6–10 km) should be considered important hydrocarbon exploration targets in the Russian Federation and the countries of Eurasian Economic Union. The first-priority oil and gas exploration targets at great depths are deeply buried horizons of the sedimentary cover of the Precaspian basin, whose subsalt hydraulic system is characterized by ubiquitous abnormally high formation pressures. The deeply buried reservoirs in the Astrakhan oil and gas accumulation zone are considered the most promising for the discovery of giant oil accumulations.

Hydrocarbon Potential of Deeply Buried Reservoirs in the Astrakhan Oil and Gas Accumulation Zone: Problems and Solutions

Global experience in oil exploration and the discovery of the Tupi field in Brazil and the Tiber field in the Gulf of Mexico in the last decade have confirmed the existence of giant oil fields with abnormally high formation pressures at depths of 10 km or greater. Until recently, the discovery of large oil accumulations in deeply buried reservoirs was considered as theoretically impossible. This work suggests that giant oil accumulations at great depths (6–10 km) should be considered important hydrocarbon exploration targets in the Russian Federation and the countries of Eurasian Economic Union. The first-priority oil and gas exploration targets at great depths are deeply buried horizons of the sedimentary cover of the Precaspian basin, whose subsalt hydraulic system is characterized by ubiquitous abnormally high formation pressures. The deeply buried reservoirs in the Astrakhan oil and gas accumulation zone are considered the most promising for the discovery of giant oil accumulations.

A dual-porosity dual-permeability model for acid gas injection process evaluation in hydrogen-carbonate reservoirs

The Pre-Caspian basin is one of the most prolific in terms of oil and gas exploration and hydrogen and carbon compounds energy production around the world. The major hydrogen and carbon compounds reservoirs are Carboniferous reef and platform hydrogen-carbonate rocks. The original fluids under subsurface conditions contain 15% hydrogen sulfide and 4% carbon dioxide. Acid hydrogen and carbon compounds reinjection is not only an environmentally friendly solution for disposal of produced greenhouse gases but also enhances oil recovery and supplies more fuel energy. On the other hand, the presence of fractures makes hydrogen-carbonate reservoir characteristics nature more complicated than conventional sandstone reservoirs, which leads to a tremendous challenge to evaluate the gas injection process. In this work, a dual-porosity dual-permeability formulation was used to model the dual-medium nature incorporating matrix system with high porosity and low permeability and fracture network with low porosity and high permeability. After matching PVT experiments, a ten pseudo-components fluid model was generated for running compositional simulation. The miscible hydrogen and carbon compounds injection was simulated as an effective enhanced oil recovery approach. Sensitivity analysis such as timing of injection gas, injection rate, well spacing and completion interval have proposed the optimal condition for the miscible hydrogen and carbon compounds flooding. The recommended optimum hydrogen and carbon compounds injection scenario is twice higher oil recovery compared with natural depletion. The results of this study illustrate further the practicability of pseudo-components splitting and lumping for compositional simulation to evaluate the performance of hydrogen and carbon compounds injection processes, and are of great importance using the dual-porosity dual-permeability method performing numerical simulation of naturally fractured hydrogen-carbonate reservoirs.

Geology-engineering integration for low-permeability and thin marginal reservoirs: a case study on Zanazour oilfield, Pre-Caspian Basin

Geology-engineering integration for low-permeability and thin marginal reservoirs: a case study on Zanazour oilfield, Pre-Caspian Basin

Lithological types and characteristics of carbonate open platform in pre-Caspian basin

The Carboniferous KT-II carbonate formation in N Oilfield at the eastern edge of pre-Caspian Basin has been developed in open marine carbonate platform. The present work aims to make an evaluation on the physical properties of limestone reservoirs, in order to identify the causes for strong heterogeneity. In the study area, limestone rocks are dominant and diverse that can be divided into fifteen types based on the grain contents: algal limestone, foraminifera limestone, fusulinid limestone, bioclast limestone, algal skeletal limestone, and oolitic limestone, etc. The oolitic limestone, algal limestone and algal skeleton limestone have the best physical properties and constitute the most favourable reservoirs in KT-II formation.

A Semi-Analytical Method for Modeling Two-Phase Flow Behavior in Fractured Carbonate Oil Reservoirs

It is quite common for oil/gas two-phase flow in developing fractured carbonate oil reservoirs. Many analytical models proposed for black oil wells in fractured carbonate reservoirs are limited to single-phase flow cases and conventional methods have been the use of numerical simulations for this problem. In this approach, a novel semi-analytical method is proposed to integrate the complexities of phase change, pressure-dependent pressure-volume-temperature (PVT) properties, two-phase flow behavior, and stress-dependent fracture permeability characteristics. A dual-porosity, black oil model considering the phase change and two-phase flow is applied to model the fractured carbonate reservoirs. To linearize the model, only flow equations of oil phase are used to develop the mathematical model. Nonlinear parameters and producing gas–oil ratio (GOR) are updated with coupled flowing material balance equations, followed by a novel proposed procedure for history matching of field production data and making forecasts. The semi-analytical method is validated with a commercial simulator Eclipse. The results show that both of the production rate curves of oil and gas phase using the proposed model coincide with the numerical simulator. The results also show that the effects of pressure-dependent fracture permeability, fracture porosity, and exterior boundary on production rate are significant. Stress sensitivity influences production rate during the whole process, reducing the cumulative production. Fracture porosity influences production rate during the intermediate flow periods. The exterior boundary affects production rate mainly in the early and intermediate production periods. Finally, a field example from the eastern Pre-Caspian basin is used to demonstrate the practicability of the method. Acceptable history match is achieved and the interpreted parameters are all reasonable.

Нефтегазоперспективные объекты палеозойского подсолевого разреза Прикаспийской впадины

Нефтегазоперспективные объекты палеозойского подсолевого разреза Прикаспийской впадины

An evaluation on mechanisms of miscibility development in acid gas injection for volatile oil reservoirs

Produced gas containing the acid gas reinjection is one of the effective enhanced oil recovery methods, not only saving costs of disposing acid gases and zero discharge of greenhouse gases but also supporting reservoir pressure. The subsurface fluid from the Carboniferous carbonate reservoir in the southern margin of the Pre-Caspian basin in Central Asia has low density, low viscosity, high concentrations of H2S (15%) and CO2 (4%), high solution gas/oil ratio. The reservoir is lack of fresh water because of being far away onshore. Pilot test has already been implemented for the acid gas reinjection. Firstly, in our work a scheme of crude oil composition grouping with 15 compositions was presented on the basis of bottomhole sampling from DSTs of four wells. After matching PVT physical experiments including viscosity, density and gas/oil ratio and pressure–temperature (P–T) phase diagram by tuning critical properties of highly uncertain heavy components, the compositional model with phase behavior was built under meeting accuracy of phase fitting, which was used to evaluate mechanism of miscibility development in the acid gas injection process. Then using a cell-to-cell simulation method, vaporizing and/or condensing gas drive mechanisms were investigated for mixtures consisting of various proportions of CH4, CO2 and H2S in the gas injection process. Moreover, effects of gas compositions on miscible mechanisms have also been determined. With the aid of pressure-composition diagrams and pseudoternary diagrams generated from the Equation of State (EoS), pressures of First Contact Miscibility (FCM) and Multiple Contact Miscibility (MCM) for various gases mixing with the reservoir oil sample under reservoir temperature were calculated. Simulation results show that pressures of FCM are higher than those of MCM, and CO2 and H2S are able to reduce the miscible pressure. At the same time, H2S is stronger. As the CH4 content increases, both pressures of FCM and MCM are higher. But incremental values of MCM decrease. In addition, calculated envelopes of pseudoternary diagrams for mixtures of CH4, CO2 and H2S gases of varying composition with acid gas injection have features of bell shape, hourglass shape and triangle shape, which can be used to identify vaporizing and/or condensing gas drives. Finally, comparison of the real produced gas and the one deprived of its C3+ was performed to determine types of miscibility and calculate pressures of FCM and MCM. This study provides a theoretical guideline for selection of injection gas to improve miscibility and oil recovery.

Comparison of the chemical flood recovery efficiency via experimental studies on the Pre-Caspian Basin core samples

Comparison of the chemical flood recovery efficiency via experimental studies on the Pre-Caspian Basin core samples

Petrophysical Characterization and Fractal Analysis of Carbonate Reservoirs of the Eastern Margin of the Pre-Caspian Basin

Petrophysical properties including pore structure and permeability are essential for successful evaluation and development of reservoirs. In this paper, we use casting thin section and mercury intrusion capillary pressure (MICP) data to investigate the pore structure characterization, permeability estimation, and fractal characteristics of Carboniferous carbonate reservoirs in the middle blocks of the eastern margin of the Pre-Caspian Basin. Rock casting thin sections show that intergranular and intragranular dissolution pores are the main storage spaces. The pore throats greater than 1 μm and lower than 0.1 μm account for 47.98% and 22.85% respectively. A permeability prediction model was proposed by incorporating the porosity, Swanson, and R35 parameters. The prediction result agrees well with the core sample data. Fractal dimensions based on MICP curves range from 2.29 to 2.77 with an average of 2.61. The maximum mercury intrusion saturation is weakly correlated with the fractal dimension, while the pore structure parameters such as displacement pressure and median radii have no correlation with fractal dimension, indicating that single fractal dimension could not capture the pore structure characteristics. Finally, combined with the pore types, MICP shape, and petrophysical parameters, the studied reservoirs were classified into four types. The productivity shows a good correlation with the reservoir types.

Genetic research of fractures in carbonate reservoir: a case study of NT carbonate reservoir in the pre-Caspian basin

The degree of development and characteristics of fractures are key factors for the appraisal of carbonate reservoirs. In this paper, core data and well logging data from the NT oilfield in the Pre-Caspian Basin are used to study the formation mechanism and distribution characteristics of different genetic fractures, and analyze their influence on reservoir properties. Fractures in carbonate reservoirs can be divided into three categories according to their formation mechanism; these are tectonic fracture, dissolved fracture, and diagenetic fracture,which is further divided into interlayer fracture and stylolite. Fractures of different formation mechanism influence fluid seepage in different degree, tectonic fractures possessing strong connecting ability to pores, and dissolved fractures also improving reservoir properties effectively, however, diagenetic fractures contributing relatively little to fluid seepage.

Lower permian reef-bank bodies’ characterization in the pre-caspian basin

Reef-bank reservoir is one of the targets for exploration of marine carbonate rocks in the Pre-Caspian Basin. Within this basin, the reef-bank bodies were primarily developed in the subsalt Devonian-Lower Permian formations, and are dominated by carbonate platform interior and margin reef-banks. The Lower Permian reef-bank present in the eastern part of the basin is considered prospective. This article provides a sequence and sedimentary facies study utilizing drilling and other data, as well as an analysis and identification of the Lower Permian reef-bank features along the eastern margin of the Pre-Caspian Basin using sub-volume coherence and seismic inversion techniques. The results indicate that the sub-volume coherence technique gives a better reflection of lateral distribution of reefs, and the seismic inversion impedance enables the identification of reef bodies’ development phases in the vertical direction, since AI (impedance) is petrophysically considered a tool for distinguishing the reef limestone and the clastic rocks within the formation (limestone exhibits a relatively high impedance than clastic rock). With this method, the existence of multiple phases of the Lower Permian reef-bank bodies along the eastern margin of the Pre-Caspian Basin has been confirmed. These reef-bank bodies are considered good subsalt exploration targets due to their lateral connectivity from south to north, large distribution range and large scale.

Depositional environments, microfacies, and stratigraphic architecture of the Kashagan isolated buildup (Carboniferous), Pre-Caspian Basin, Kazakhstan

Depositional environments, microfacies, and stratigraphic architecture of the Kashagan isolated buildup (Carboniferous), Pre-Caspian Basin, Kazakhstan

First results of U–Pb dating of detrital zircons from the Ordovician clastic sequences of the Sol-Iletsk Block, East European Platform

The first LA–ICP–MS U–Pb isotopic ages of detrital zircons from the Ordovician sandstones of the Sol–Iletsk Block (well 2–Ordovician), located at junction of the East European Platform with the Pre-Caspian Basin and the Pre-Uralian foredeep, are presented. Two detrital zircons with well-defined ages of 561 ± 4 and 570 ± 5 Ma were found in sample K15–501. They confirm the Ordovician age of the sandstones, which earlier had been defined on the basis of seismic–stratigraphic and lithological correlations. The age distribution of the detrital zircons indicates the significant role of Late Precambrian rocks as provenance sources. However, those rocks still remain unknown in the Early Precambrian basement of the Volga–Ural part of the EEP.